Electricity is a ‘just-in-time’ commodity, necessitating that supply and demand of power be balanced in order to maintain specified frequency and voltage. The electric demand or load varies based on the needs of connected industrial, commercial, or residential customers for lighting, HVAC, electronics and appliances, pumps and motors, etc. Electricity demand displays patterns that are influenced by the level of macro-economic activity, weather, customary working hours, time-of-day, as well as many other factors.
Electric generation must supply the demand, generally in the most economic manner, given constraints on fuel cost/availability, power plant operating/maintenance condition, availability of cooling for heat engines, and transmission costs or capacity constraints. Generating units are generally dispatched in merit order, based on the marginal cost of generation, with the most economical operated the most and supplying the ‘base load.’ In addition to the marginal cost of operation, which is proportional to the cost of fuel and other variable costs such as an overhaul accrual, generating units also have startup cost for fuel and wear-and-tear to bring them from a cold condition to an operating condition. Accordingly, some generating units may be placed in a ‘hot standby’ condition, if the standby operating costs are less than the startup costs, and the unit is required to meet anticipated demand or reserve margins.
The marginal operating cost will determine when a generating unit is dispatched and how many megawatt-hours it will produce. In a regulated integrated utility responsible for generation, transmission and distribution, the fixed costs for capital amortization are covered as return on invested capital mandated by utility commissions or other rate setting entities. With the introduction of electric markets, independent power producers (IPPs) must cover fixed costs and profit from the difference between the price of electricity and the marginal cost to generate power. This creates a tension between the efficiency of a new generating unit and the cost to build it, as novel efficiency measures must pay for themselves as well as a risk premium. The book value of a power plant is first cost less accumulated amortization offset by improvements, but its market value may be for example determined as the net present value of discounted cash flows, which depends on the investors' return requirements and forecasts of the cash flows. The cash flow forecasts are influenced by the economic dispatch order, which may change based on fuel costs or if newer and more efficient units are constructed.
Because sunlight is free, solar power plants have very low marginal costs and are always at the front of the dispatch queue, and in some jurisdictions are mandated to be dispatched first. However solar power plants are relatively expensive to construct ($3 to $6 per watt, for example), and their low capacity factor (typically less than 25% of nameplate), requires a high price for electricity to cover the fixed costs and profit. As a matter of public policy, various countries and utility markets provide incentives to encourage construction of solar power plants, using mechanisms such as:                renewable energy pricing policy such as feed-in tariffs (FITs) or power purchase agreements (PPAs) offering a guaranteed payment per kilowatt-hour;        tax policy such as investment or production tax credits and accelerated depreciation;        environmental policy such as carbon credits or taxes and renewable portfolio standards.        
The most important of these has been pricing policy, because it is revenue that is most important in determining whether an investment in a new power plant will be profitable, and revenue certainty reduces the financial risk premium. Energy pricing policy has favored solar thermal power plant designs that resemble base load plants with high efficiency, and has dis-favored load following capability. Feed in tariffs may also favor smaller power plants with higher capacity factors obtained by thermal energy storage. As renewable power has become competitive, these incentives are being reduced or eliminated, and renewable power plants will be expected to consider regulatory, market, commodity, and technology risks, similar to conventional power plants
Rankine Steam Cycles are commonly used to convert thermal to electric energy. Raising the steam temperature tends to increase the power conversion efficiency, permitting a smaller amount of heat (e.g., fossil or solar) to produce the same power. Regenerative feedwater heating also increases efficiency, but at the expense of reduced power output for the same steam flow. Raising the pressure tends to increase the specific work (per unit of steam flow), permitting more power for the same size power block. Above pressures of about 50 to 75 bar, depending on the superheated steam temperature, the expanding steam may begin to condense within the turbine, potentially damaging the turbine by erosion. Accordingly at higher pressures, some form of reheat is required to avoid harmful condensation in the low pressure stage of the turbine. These and other factors determine the most economical steam conditions and steam cycle for use in a thermal power plant.
Because solar fields are expensive, by conventional thinking it is desirable to increase the thermal to electric efficiency of the power block by increasing the temperature and adding regenerative feedwater heating. These steps result in the use of expensive and sometimes exotic materials, manufacturing, and construction measures. These steps tend to reduce the nameplate power output of the turbine-generator (per unit of steam flow), increase startup time, and reduce load following capability.
As more renewable generation is installed, load following becomes more important than base load power. Consequently there is an increasing need for generating units with resiliency and flexibility to follow load.
The “Duck Curve” illustrates the challenge of managing a green grid. As can be seen in FIG. 1, the California Independent System Operator (CAISO) Base Load is being reduced as solar power ramps up its generation during the daytime. As the installed base of PV generation increases over the years, the afternoon ‘hump’ disappears and becomes an increasingly large depression causing two gigawatt-scale problems:                overgeneration risk occurs because thermal generation resources must continue to operate to be available when the preferred renewable resources become unavailable, as the sun sets for example;        ramp need occurs as the evening load increase coincides with the decreasing output from solar power.        
Ironically, the conventional modern solar thermal power plant is not well suited to this regime. Without thermal storage, such plants contribute to the ‘Duck Curve’ depression. By adding thermal energy storage, conventional solar thermal plants can address overgeneration by operating during the evening peak rather than during the afternoon depression. But their base load approach to power block design means these plants are not well suited to load following and cannot materially address the steep ramps.